In the oil and gas industries it is commonplace for coiled tubing to be used for well drilling or other well bore operations, such as deploying reeled completions equipment, logging high angled boreholes, positioning tools, instruments, motors and the like, and/or deploying treatment fluids.
Coiled tubing is formed as a continuous string of pipe and therefore in many applications it is easier and faster to deploy into a well than conventional pipe, particularly in horizontal or multi-lateral wells. Most coiled tubing strings installed into well bores are composed of a steel material, which is injected into the well with a hydraulically activated injector head that has two opposed rolling surface areas that effectively push the tubing into the well from above the well head, using friction to ensure control and movement of the tubing into the well bore and thereby exerting compressive forces on the tubing. The coiled tubing is typically small in diameter, usually a tubing having an outside diameter of about 1.5 cm to 9 cm, and sufficiently flexible to be coiled onto a drum to form the tube reel. Coiled tubing is thus relatively easy to store and transport, and may be provided in long sections (typically 6,500 meters) such that the tubing may be deployed relatively quickly.
Typically, the coiled tubing is shipped, stored, and used on the same coiled tubing reel. Coiled tubing reels are deployed from trucks or trailers for land-based wells and from ships or platforms for offshore wells. When spooling or unspooling coiled tubing from a reel, the tubing is subjected to bending forces that can cause tubing fatigue. This fatigue is a major factor in determining the useful life of a coiled tubing work string. Coiled tubing reels typically rely on hydraulic power to operate the reel drive, brake, and spooling guide systems. Most coiled tubing reels can be powered in “in-hole” [i.e. running-in-hole (RIH)] and in “out-hole” [i.e. pulling-out-of-hole (POOH)] directions.]
The reel drive and its associated motor provide the reel back-tension, that is the tension in the coiled tubing between the reel and the injector that is used to spool and unspool the tubing from the reel, prevent tubing sagging between the reel and the injector while running coiled tubing into or out of the wellbore, and keep the wraps of tubing secure on the reel. When coiled tubing is moving out of the well, the reel exerts a force as the tubing is bent and then secured onto the reel. This force imparts both elastic and plastic deformation energy into the tubing as it is bent. Conversely, as the tubing is moved into the well, the elastic energy along with the energy imparted to keep the tubing wraps tightly secured to the reel must be dissipated. This energy is normally dissipated as heat in the hydraulic system, or may be dissipated in a separate braking system.
Conventional coiled tubing operation equipment typically includes coiled tubing spooled on a reel to be dispensed onto and off of the reel during an operation; an injector to run coiled tubing into and out of a well; a gooseneck affixed to the injector to guide the coiled tubing between the injector and the reel; a control cab with the necessary controls and gauges; and a power source. Additional or auxiliary equipment also may be included. Coiled tubing equipment, such as that described in U.S. Pat. No. 6,273,188 (McCafferty et al.), which incorporated herein by reference, is widely known in the industry.
In a typical coiled tubing configuration, the power source comprises a diesel motor that is used to operate one or more hydraulic pumps. The motor, pump(s) and other functions of the unit are controlled from the control cab. Between the injector head and the reel resides the tubing guide or gooseneck. The tubing extends from the reel to an injector. The injector moves the tubing into and out of the wellbore. Between the injector and the reel is a tubing guide or gooseneck. The gooseneck is typically attached or affixed to the injector and guides and supports the coiled tubing from the reel into the injector. Typically, the tubing guide is attached to the injector at the point where the tubing enters the injector, and serves to control the entry of the tubing into the injector.
As the tubing wraps and unwraps on the reel, the point of contact with the stored tubing moves from one side of the reel to the other (side to side) and the gooseneck controls the bending radius of the tubing as it changes direction. The gooseneck typically has a flared end that accommodates this side to side movement. Goosenecks are widely known in the field, including those disclosed in U.S. Pat. Application 2004/0020639 (Saheta, et al.), which is incorporated herein by reference.
Conventional injector heads include a chain drive arrangement which acts as a coiled tubing conveyor. Two loops of chain are provided, typically carrying blocks which grip the tube walls. The chains are mounted on sprockets driven by hydraulic motor(s), using fluid supplied from the power pack. Such coiled tubing units have been in use for many years.
However, the Applicant has identified a number of problems associated with the existing apparatus. For example, the force which must be applied to the tubing by the injector head is usually considerable, and requires that the tubing is clamped tightly between the blocks carried by the driven chains. These large forces may also result in permanent radial deformation of the tubing, a phenomenon known in the industry as “slip crushing.” When slip crushing occurs in the injector, that section of tubing may shrink until it stops transferring axial load to the injector, which in turn may increase the tubing stresses in other parts of the gripping area, potentially leading to complete loss of gripping. Slip crushing also renders the tubing unsafe for use and must therefore be replaced at great expense.
Further, the apparatus often operates in difficult conditions, and the injector head is continually exposed to a variety of fluids carrying various particulates that can wear down parts of the apparatus, such that frequent maintenance is required. Also, a fundamental problem with conventional injectors is that many of the modes of injector failure cause the tubing to fall freely into the well, or conversely, be ejected by pressure forces from the well. Such modes of failure include motor failure, brake failure, chain failure, cavitation, loss of hydraulic oil, shaft breakage, gripper loss, etc. Finally, the processes and apparatus are very expensive and unreliable because of the use of elaborate equipment and apparatus means.
As such, a need exists for a method and/or a device for moving, or injecting, coiled tubing into and out of a well bore using simple devices which better maintain tubing integrity, minimize loss of coiled tube control, and/or require less maintenance.